When completing wells in earth formations, various fluids generally are used in the well for a variety of reasons. Common uses for wellbore fluids include: lubrication and cooling of drill bit cutting surfaces during general drilling operations or drilling in a targeted petroliferous formation, suspending dislodged formation pieces and transporting them to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability and minimizing fluid loss into the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
Wellbore fluids or muds may include a base fluid, which is commonly water, diesel or mineral oil, or a synthetic compound. Weighting agents (most frequently barium sulfate or barite is used) may be added to increase density, and clays such as bentonite may be added to help remove cuttings from the well and to form a filtercake on the walls of the hole.
Wellbore fluids also contribute to the stability of the well bore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow, or in undesired cases, the blow out of formation fluids or the collapse of pressured earth formations. The column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid. High-pressure formations may utilize a fluid with a density as high as about 10 pounds per gallon (ppg) and in some instances may be as high as 21 or 22 ppg.
Oil-based muds (OBMs) have been used because of their flexibility in meeting density, inhibition, friction reduction and rheological properties desired in wellbore fluids. The drilling industry has used water-based muds (WBMs) because they are inexpensive. The used mud and cuttings from wells drilled with WBMs can be readily disposed of onsite at most onshore locations. WBMs and cuttings can also be discharged from platforms in many U.S. offshore waters, as long as they meet current effluent limitations guidelines, discharge standards, and other permit limits.
One specific category of wellbore or completion fluids include annular fluids or packer fluids, which are pumped into annular openings in a wellbore such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C-annulus in a wellbore comprising at least an A-, B- and C-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string. Yet alternatively, said one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellbores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or pipe(s) but external to said one or more strings of pipe therein.
Such packer fluids primarily serve to protect the casing but also serve to provide hydrostatic pressure in order to equalize pressure relative to the formation, to lower pressures across sealing elements or packers; or to limit differential pressure acting on the well bore, casing and production tubing to prevent collapse of the wellbore, and/or help control a well in the event of a leak in production tubing or when the packer no longer provides a seal or has been unseated. While the packer fluids may be formulated with sufficient density to perform such functions, conventionally, solid weighting agents that are often used in other wellbore fluids are avoided in packer fluids due to the concerns of solid settlement, particularly because packer fluids often remain in the annulus for extended periods of time without circulation. Further, in addition to serving the above mentioned conventional functions, for packer elements that are activated by the packer or annular fluid, the fluid may also be formulated with such additional consideration in mind.
Another category of wellbore or completion fluids include open hole fluids for uncased portions of the well. The fluids are pumped into a vertical or high angle section of a wellbore where the target producing or injection formation often remains exposed during production or injection and/or may include any of the following: swellable packers, external casing packers, perforated liners, sand control screens or sand screens, basepipe, and/or selected inflow control devices which may or may not include gauges, control lines and even submersible pumps. Often, the open hole fluid is spotted in the open hole prior to and functions to facilitate the installation of any of the aforementioned. In the example of a swellable packer/polymer(s), the open hole fluid may provide functionality such that the packer/polymer expands, thus providing a barrier to control pressure, movement of fluids and enhance integrity of the lower installation.
According, there is a continuing need for improvements in wellbore fluids to have sufficient density and meet other considerations that may be particularly desirable for use with packer elements and/or swellable polymers used in wellbores and open hole.